Stringent environmental standards of emissions of sulfur compounds, together with low sulfur specifications for fossil fuel products, have resulted in making sulfur management critical in modern power generation and energy use. Some processes where such sulfur management is important include gasification or liquefaction of coal, smelting of various sulfide containing ores, the sweetening of sour natural gas, oil refining, petrochemical production, destructive distillation of coal and oil shale, and the production and use of hydrogen sulfide containing geothermal steam and liquid for generating electricity. As modern power generation equipment process fossil fuel products with higher sulfur contents, the need for more efficient, low cost sulfur recovery processes will also increase.
Sulfur species, such as H2S and COS, are generally removed from the gas or liquid stream before further processing occurs. The usual sulfur species removal process involves an amine or similar scrub to separate the sulfur species. This involves passing the gas stream through a liquid containing an amine such as monoethanolamine (MEA), diethanolamine (DEA), triethanolamine (TEA), diglycolamine (DGA), or monodiethanolamine (MDEA) with or without proprietary additives, or through use of a physical solvent such as methanol or sulfalane, or various combinations of these. The sulfur species are retained in the liquid solution as a result of their reaction with the amines and or physical absorbtion. Once most of the amines in the solution have reacted or the solvent is loaded, the amine solution is regenerated in a step known as stripping. Here, the sulfur species are liberated from the solution by pressure reduction, the application of heat to increase vapor pressure, the cleavage of the nitrogen-sulfur chemical bond, and the contacting of this material with a stripping medium such as steam. Next, in a process conducted separate from the original gas stream, the sulfur species are converted to elemental sulfur by a sulfur recovery process, which is typically carried out at low pressure. Examples of sulfur recovery processes include conventional, also known as modified, Claus processes, and sub-dewpoint Claus processes, such as cold-bed adsorption and associated tail gas conversion processes, which typically achieve over 98% sulfur recovery.
There are several problems with these sulfur species removal processes. First, in the process of removing the sulfur species from the gas stream, other acid gases, such as CO2, and hydrocarbon fuel components are removed as well. The retention of these other acid gases or fuel components in the gas stream is desirable because their presence generates energy and/or power for example when the gas is burned and expanded in a gas turbine. Second, the sour gas stream is often at a much higher temperature and/or pressure than the sulfur species removal processes can accommodate. For example, sour syngas streams produced by the gasification of coal usually have temperatures above 250° F., while absorption or reaction of sulfur species with amine is favored at high partial pressures and low temperatures, typically 80-140° F. Adjusting the temperature and/or pressure of the sour gas stream to accommodate current sulfur species removal processes adds additional equipment and greater complexity to a plant with concurrent increases in cost. Therefore, processes that address these problems would help increase the efficiency of modern energy and power generation equipment.
One process is currently available which directly reacts the sulfur species in a syngas stream to sulfur without first treating them with a sulfur species removal system. This process is called “Selective Catalytic Oxidation of Hydrogen Sulfide” (SCOHS) (Department of Energy website, http://www.netl.doe.gov/coalpower/gasification/gas-clean/index.html (viewed Oct. 22, 2003)). This process has limitations however. First, the catalyst which converts the sulfur species to elemental sulfur comprises activated carbon, unlike the alumina catalyst used in most conventional and sub-dewpoint Claus sulfur recovery processes. Second, SCOHS operates at temperatures below 300° F., and preferably below 250° F., which is only slightly above the melting point of sulfur. A new process that would be adaptable for use with current Claus sub-dewpoint reactor and catalyst technology and would operate at higher temperatures would represent a significant advance in the art.
The present invention solves these problems and provides a new method of removing sulfur species from a sour gas stream.